Wellbore fluids are utilized in the construction, repair or treatment of wellbores such as those that are drilled through earth formations in order to access reservoirs of oil, gas or water, or to access geothermal heat.
The term “wellbore fluid” as used herein means any liquid that serves a useful function when it is placed in a well during the processes of well construction, well treatment, or the repair of a well.
The wellbore fluids of the present invention are suitable for use in a variety of wellbores including wellbores assigned to oil and/or gas production, water or gas injection wellbores, water production wellbores, and geothermal wellbores.
Wellbore fluids used during well construction include drilling fluids, lost circulation control fluids, spotting fluids such as those used to help free drill pipe that has become stuck in the well, under-reaming fluids, completion fluids such as brines used to control formation pressures, perforating pills, brine loss-control pills (a “pill” is a relatively small volume of wellbore fluid, usually less than 200 barrels, that is pumped into the desired position in a wellbore to accomplish its function), fluids used during gravel-packing operations, cement slurries, and packer fluids.
Wellbore fluids typically used as well-treatment fluids include clean-up fluids that are pumped to effect the removal of residues from the well, acidic treatment fluids, fracturing fluids, and viscous fluids pumped into a permeable formation for the purpose of diverting flow into other formations or for shutting-off the flow of produced water.
Wellbore fluids used during well repair (“workover”) operations include workover fluids such as a kill fluid that is pumped into a well, the kill fluid having sufficient density to stop (“kill”) the production of formation fluids. Workover operations include the milling out of old downhole hardware, and can use any of the fluids listed above as required to effect the repair or re-completion of the well.
Drilling fluids are utilized when drilling a wellbore through rock formations in order to sweep the rock cuttings created at the bit up to the surface where they are removed. To control downhole pressures, the fluid's density is usually increased by the addition of a powdered dense mineral such as barite. The fluid should therefore exhibit sufficient viscosity to provide efficient cuttings removal (hole-cleaning), and sufficient gel strength for the stable suspension of barite. Drilling Fluids should also exhibit a low filtration rate (Fluid Loss) in order to lessen the possibility of differential sticking.
Completion fluids are utilized during operations that take place in the so-called completion phase of wellbore construction, which is after drilling the wellbore and before commencement of production of fluids into the wellbore (or before injection of fluids from the wellbore into a rock formation). Frequently a completion fluid will need to be viscosified to transport or suspend dispersed solid particles, and water-soluble polymers are also used to minimize the loss of completion fluid or filtrate into the permeable formation.
Treatment fluids may be utilized intermittently during the life of a wellbore, for example, when conducting stimulation or remedial operations in a rock formation penetrated by the wellbore. For example, where the treatment fluid is a fracturing fluid, it is highly desirable that the solid proppant particles that may be added to the fracturing fluid are swept efficiently along the length of the induced fractures so that the fracture remains propped open when the pumping pressure ceases. This often requires a viscosifying agent to be added to the fluid. It is also beneficial if the polymer solution reduces the rate of leak-off of the fracturing fluid into the permeable formation so that the hydraulic pressure is most effectively transmitted to the tip of the growing fracture.
Where a fracturing or other wellbore fluid is pumped at high flow rates it can enter a turbulent flow regime causing unwanted high pressure gradients. The turbulent flow and the pressure losses can be minimized by adding relatively smaller amounts (than used for viscosification) of a friction reducer.
After tubular steel liner or casing is run into a well, cement is pumped to seal the annular gap between the steel and the formation. Polymers are often added to the cement slurry to reduce the fluid loss (filtration rate) and to minimize settlement (free water).
As more and more challenging conditions are encountered in wellbore operations, there has arisen a need for improved performance water-based wellbore fluids comprising a synthetic polymeric viscosifier that exhibits improved tolerance to high temperatures and to electrolytes.
More specifically, there is a need for high-performance rheology modifiers used in water-based drilling fluids. The enhanced performance of the drilling fluids especially the High Pressure/High Temperature (HP/HT) compatibility will allow faster and safer drilling. A rheology modifier is a critical component in water-based drilling fluids to ensure a proper rheology profile which performs specific functions such as suspending weighting agents and hole cleaning. Xanthan Gum is one of the most commonly used rheology modifiers in water-based drilling fluids. Xanthan gum was known to start losing rheological properties at above 250° F. so it is not suitable for HP/HT drilling operations. A desired rheology modifier should possess similar rheological properties (e.g., highly shear thinning) with enhanced salt tolerance and thermal stability. These enhanced properties will allow successful drilling operations under HP/HT conditions. Development of such a salt-tolerant, thermally-stable rheology modifier is critically important to the drilling industry. HP/HT compatible water-based drilling fluid will allow more environmentally friendly drilling operations in a safe and efficient manner. Without a high performance rheology modifier, such drilling operations under HP/HT conditions are extremely challenging.